1. Field of the Invention
The invention relates generally to single roller cone drill bits for drilling boreholes in earth formations. More specifically, the invention relates to a single cone bit with interchangeable cutting structures, a box-end connection, and integral sensory devices for evaluation of the formation and bit health.
2. Background Art
One aspect of drilling technology relates to roller cone drill bits are used to drill boreholes in earth formations. The most common type of roller cone drill bit is a three-cone bit, with three roller cones attached at the end of the drill bit. When drilling smaller boreholes with smaller bits, the radial bearings in three-cone drill bits become too small to support the weight on the bit that is required to attain the desired rate of penetration. In those cases, a single cone drill bit is desirable. A single cone drill bit has a larger roller cone than the roller cones on a similarly sized three cone bit. As a result, a single cone bit has bearings that are significantly larger that those on a three cone bit with the same drill diameter.
FIG. 1A shows a prior art single cone drill bit. The single cone bit 1 includes one roller cone 4 rotatably attached to a bit body 16 such that the cone""s drill diameter is concentric with the axis of rotation 6 of the bit 1. The roller cone 4 has a hemispherical shape and typically drills out a bowl shaped bottom hole geometry. The drill bit 1 includes a threaded connection 14 that enables the drill bit 1 to be connected to a drill string (not shown). The male connection shown in FIG. 1A is also called a xe2x80x9cpinxe2x80x9d connection. A typical single cone bit is disclosed in U.S. Pat. No. 6,167,975, issued to Estes.
FIG. 1B shows a cross section of a prior art drill bit 1 drilling a bore hole 3 in an earth formation 2. The roller cone 4 is rotatably mounted on a journal 5 that is connected to the bit body 16.
Another aspect of drilling technology involves formation evaluation using sensors that detect the properties of the formation, such as resistivity, porosity, and bulk density. Formation evaluation allows a well operator to know the properties of the formation at various depths so that the well can be developed in the most economical way. Three of the sensors known in the art that are used for formation include button resistivity sensors, density logging sensors, and neutron logging sensors, each of which will now be described.
A button resistivity tool includes a number of electrode buttons, for example three buttons, that are placed into contact with the borehole wall. One of the buttons injects an electrical current into the formation, and the potential difference is measured between the other two buttons. The potential difference is related to the resistivity of the formation. Button resistivity tools are described with more detail below in the discussion of measurement-while-drilling applications.
A density logging tool uses back scattered radiation to determine the density of a formation. A typical density logging tool is described in U.S. Pat. No. 4,048,495, issued to Ellis, and is shown in FIG. 2. The density logging tool 20 is shown disposed in a borehole 3 on a wireline 10. The tool 20 includes a caliper 5 that positions the tool 20 so that the source 24 and sensors 21, 22 of the tool 20 are pressed into the mud-cake layer 23, as close as possible to the borehole wall 12.
The density logging tool 20 contains a gamma ray source 24, typically Cesium-137, that emits medium energy gamma rays into the formation. The source 24 is enclosed in shielding 26 that shields the detectors 21, 22 from gamma rays coming directly from the source 24. The front face 29 of the tool includes a window 25 that enables a collimated beam of gamma rays to be transmitted into the formation 2. Through a process called xe2x80x9cCompton scattering,xe2x80x9d the gamma rays scatter back into the borehole and into the detectors 21, 22.
Compton scattering is the interaction of a gamma ray with electrons. When a gamma ray interacts with an electron, it imparts part of its energy to the electron, and the gamma ray changes direction. Through one or more Compton scattering events, gamma rays can be scattered back into the borehole. The number of scattering events that occur depends on the density of electrons in the material into which the gamma rays are transmitted. Because the density of electrons depends on the density of the material, a density logging tool can measure the density of a formation by measuring the number of gamma rays that are back scattered in the formation and return to the borehole where they can be detected by the tool.
A typical density logging tool 20 contains two gamma ray detectors, a short-spaced detector 22, and a long-spaced detector 21. The long-spaced detector 21 is located about 36 cm from the source 24. Because of the distance between the source and the long-spaced detector 21, the long-spaced detector receives gamma rays that are mostly scattered deep in the formation 2. Further, the front face 27 of the density tool has a window 28 over the long-spaced detector 21. The window 28 is shaped to collimate the gamma rays so that those gamma rays that are received in the detector 21 are even more likely to have scattered relatively deep in the formation 2 and not the mud-cake layer 23. Even with the location of the long-spaced detector 21 and the collimating window 28, the density computed by the long-spaced detector 21 is still affected by the density of the mud-cake layer 23, which the gamma rays must pass through twice. Thus, the density value computed from the long-spaced detector 21 is strongly affected by the density of the mud-cake layer 23.
The density measured by the long-spaced detector 21 can be corrected using the short-spaced detector 22, which is typically located about 11 cm from the source. The short-spaced detector 22 receives back scattered gamma rays that have scattered in materials close to the borehole wall 3, like the mud-cake layer 23. Again, a window 29 in the front face 27 of the tool 20 collimates the incoming gamma rays so as to increase the chance that detected gamma rays were scattered in the mud-cake layer 23. By combining the measurements of the two detectors 21 and 22, a corrected value for the formation density can be computed, as is known in the art.
A neutron logging tool makes a measurement corresponding to the porosity of a formation. A typical neutron logging tool is disclosed in U.S. Pat. No. 4,035,639 issued to Boutemy et al. A neutron logging tool contains a neutron source, typically an Americium-Beryllium source, and a neutron detector. The source emits high energy neutrons, also called xe2x80x9cfastxe2x80x9d neutrons, into the formation. The fast neutrons lose energy as they collide with atoms in the formation, eventually becoming slow neutrons, also called xe2x80x9cthermalxe2x80x9d neutrons. Thermal neutrons will randomly migrate in the formation. Some of the migrating thermal neutrons will migrate back into the borehole. A neutron logging tool detects the thermal neutrons that randomly migrate back into the borehole.
Hydrogen atoms, with an atomic number of one, have approximately the same mass as a neutron. Because of their similar mass, a neutron loses much more energy in collisions with hydrogen atoms than it does in collisions with any other atom. Thus, the rate at which fast neutrons become thermal is related to the number of hydrogen atoms in the moderating material. As a result, the number of thermal neutrons detected by the neutron logging tool is related to the number of hydrogen atoms in the formation. Because water and hydrocarbons have a similar amount of hydrogen atoms, the neutron logging tool measures how much of the formation is occupied by water and hydrocarbons. In non-gas bearing formations, a measurement from a neutron logging tool is related to the formation""s porosity.
FIG. 3 shows a wireline neutron logging tool 30. A source 31 is located in the tool 30 surrounded by shielding 32. The example neutron logging tool 30 in FIG. 3 shows two detectors, 33 and 34, that are used to detect thermal neutrons and ultimately to calculate the formation porosity. The two detectors 33, 34 are spaced apart on the neutron logging tool 30. Using the known spacing of the detectors, a ratio of the count rates can be used to correct the porosity calculation for borehole shape effects.
The neutron logging tool 30 also includes a caliper 35 that serves two purposes. First, it pushes the source 32 and sensors 33, 34 into the opposite face 12 of the formation 2. Second, the distance that the caliper 35 extends to the wall 36 can be added to the tool size to compute the borehole diameter, which affects the neutron measurement.
To improve on the formation evaluation by wireline tools, well logging tools can be disposed on a drill string and measurements can be made while drilling. Such measurements are called measurement-while-drilling (xe2x80x9cMWDxe2x80x9d), or logging-while-drilling (xe2x80x9cLWDxe2x80x9d). In MWD, sensors are disposed on the drill string and used for formation evaluation during drilling operations. MWD enables formation evaluation before the drilling fluid (xe2x80x9cmudxe2x80x9d) invades the drilled formation and before a mud-cake layer is formed on the borehole wall.
FIG. 4 shows a prior art drilling system with an MWD tool 42, as disclosed in U.S. Pat. No. 5,339,036 issued to Clark et al. A drilling rig 40 is positioned over a bore hole 3 that is drilled into an earth formation 2. Typically, sensors are located in subs 41 that are positioned a few feet above the drill bit 43 on the drill string 44. In that position, the sensors can evaluate the formation 2 before significant invasion of the formation by the drilling fluid takes place.
Drilling fluid 45 is pumped down through the drill string 44 and ejected through ports in the drill bit 43. The drilling fluid 45 is used to lubricated the drill bit 43 and to carry away formation cuttings, but it also can interfere with formation evaluation. Because of the hydrostatic pressure of the drilling fluid 45 at the drilling depth, the drilling fluid 45 seeps into the formation 2. This process is called invasion. Sensors on a wireline tool (as shown in FIGS. 2 and 3) can be moved through the borehole only after drilling is stopped and the drill bit and drill string have been removed from the borehole. Often, the drilling fluid is pumped out of the borehole before a wireline tool is used. Wireline tools are often affected by the properties of the drilling fluid 45 that has invaded the formation 2. By disposing sensors in a sub or MWD collar 41 and performing formation evaluation while drilling, the measurements can be made before there is significant invasion, thereby enabling more accurate measurements.
FIG. 5 shows a cross-section of a MWD collar 50 on a drill string 44. The collar 50 surrounds the drill pipe 44. A button resistivity tool is disposed in the drill collar 50. Three button electrodes 53, 54 and 55 are shown on a blade 56 that extends radially from the collar 51. The blade 56 places the electrodes 53, 54, and 55 in contact with a borehole wall (not shown in FIG. 5), enabling accurate formation evaluation. One of the electrodes injects a electrical current into the formation, while the other two electrodes measure the potential difference between them. The measured potential difference and the distance between the two measuring electrodes are related to the formation resistivity.
By way of example only, electrode 53 in FIG. 5 could be used as the injecting electrode. Electrodes 54 and 55 would measure the potential difference that exists between them.
Even using MWD, however, there is still some invasion of the mud filtrate into the formation that causes errors in the measurements. Because the drilling fluid is pumped through ports in the drill bit, the formation is exposed to the drilling fluid for the time it takes the drill to penetrate the distance between the bit and the MWD collar. Many of these errors can be avoided if the sensors are disposed in the drill bit itself, thereby enabling the formation to be evaluated at, and even ahead of, the point where drilling is occurring.
One example of a drill bit with integral sensors is disclosed U.S. Pat. No. 5,475,309 to Hong et al. FIG. 6A shows a drill bit 61 with an integral sensor 60. Sensor 60 is a dielectric tool that measures the water content of the formation near the drill bit. The sensor 60 can evaluate the formation 2 at the drilling depth 62, before the formation 2 is penetrated by the bit 60. A sensor 60 disposed in the drill bit enables more accurate measurements because the formation is evaluated before any significant invasion of drilling fluid into the formation 2.
Another drill bit with integral sensors is shown in FIG. 6B, as disclosed in U.S. Pat. No. 5,813,480 issued to Zaleski, Jr., et al. FIG. 6B shows a three cone drill bit 68 with temperature sensors 65 located in the journal 67. The temperature sensors 65 transmit data to a telemetry or data storage system by way of a wire 68 that runs through the journal 65 and the bit body 66. If the temperature in the journal begins to rise and exceed normal operating conditions, that is a signal that the journal bearings are beginning to fail. Corrective steps, like replacing the drill bit, can be taken before a catastrophic failure occurs.
One aspect of the invention relates to a drill bit with a bit body adapted to be coupled to a drill string. The bit body also has a sensor disposed therein. A single journal is removably mounted to the bit body, and a roller cone is rotatably mounted to the journal. In some embodiments, the bit body also includes a box-end connection.
Another aspect of the invention relates to a bit body comprising a box-end connection on one end of the bit body and a journal connection on an opposite end from the box-end connection, the journal connection adapted to receive a removably mounted journal. The bit body includes a sensor mounted therein.
Yet another aspect of the invention relates to a drill bit comprising a bit body adapted to be coupled to a drill string, a single journal removably mounted to the bit body, a temperature sensor disposed in the single journal, and a roller cone rotatably mounted on the single journal. In some embodiments, the drill bit includes a sensor disposed in the bit body.
Another aspect of the invention relates to a drill bit comprising a bit body, at least one sensor disposed in the bit body, a short-hop telemetry transmitter disposed in the bit body, and a box end connection adapted to connect the drill bit to a rotary steerable system. The drill bit in this aspect of the invention also includes a single journal removably mounted to the bit body and a roller cone rotatably mounted on the journal.
Yet another aspect on the invention relates to a drill bit comprising a bit body, a box-end connection adapted to connect the drill bit to a drill string, and a sensor disposed in the bit body.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.